D I S C U S S I O N P A P E R

Increasing the Use of Natural Gas

in the Asia-Pacific Region

Ian Cronshaw, Quentin Grafton, and Llewelyn Hughes

May 2017

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1

Introduction

Increased use of natural gas in the Asia-Pacific region could bring substantial local and global benefits.

Countries in the region could take advantage of newly abundant global gas supplies to diversify their

energy mix; the United States, awash in gas supplies thanks to the fracking revolution, could expand its

exports; and climate change could slow as a result of gas displacing coal in rapidly growing economies.

However, many Asian countries have not fully embraced natural gas. In previous decades, the United

States and Europe both capitalized on low gas prices by investing in infrastructure to transport and

store gas and by creating vibrant gas trading systems. By contrast, Asian countries have not invested in

infrastructure, nor have they liberalized gas markets. Strict regulations, price controls, and rigid con-

tracts stifle gas trading. The window of opportunity for making the transition to gas is closing, as slow-

ing Asian energy demand and copious global supplies are reducing prices and discouraging global in-

vestment in infrastructure for gas trading and distribution. If supply dries up, prices could increase

markedly, making gas unattractive to Asian countries, especially when compared to coal.

Still, this scenario is not inevitable. If global gas demand increased modestly over the next decade, rais-

ing prices enough for production to be profitable but not so much that consumption became unafforda-

ble, Asian countries could invest in infrastructure and enact reforms to enable a large increase in gas con-

sumption. However, because of sluggish global economic growth, the Asia-Pacific region itself is the only

plausible source of an initial uptick in new gas demand that can support a sustained surge. A simulation of

global gas markets finds that a 25 percent increase in gas demand in both China and India, compared with

current market forecasts, could help stabilize prices. The 25 percent increase would represent just a 2.9

percent increase in global demand but would be enough to boost Asian gas prices by more than 20 per-

cent over the next decade. Such an increase in demand is plausible in both China and India, because they

are large and growing economies that use relatively little gas today as a share of their energy mix and are

motivated to use more gas to displace the burning of coal, which causes air pollution. At the same time,

because China is the world’s largest source of greenhouse gas (GHG) emissions and India is the third-

largest and fastest-growing source, gas use that replaces coal would slow global GHG emissions.

Such demand increases are not necessarily favorable for U.S. strategic interests. Russia could benefit

by selling 30 percent more gas than it currently does, primarily via pipeline to China, and U.S. produc-

ers would export less gas to Europe in favor of a more lucrative Asian market, thus exposing U.S. allies

to increased dependence on Russian gas.

Still, the United States stands to gain more than it loses by promoting a transition to gas in the Asia-

Pacific. Whether the initial increase in gas demand materializes will depend largely on domestic policy

decisions—for example on infrastructure investment or on caps on local gas prices—in China and In-

dia. The United States can encourage Chinese and Indian governments to make these decisions by

providing technical assistance to implement reforms and recommending that international institutions

provide financial assistance. U.S. policymakers should also coordinate competing proposals from Chi-

na, Japan, and Singapore to establish a thriving gas trading hub. Finally, to secure the environmental

benefits of a transition to gas, the United States should develop best practices for measuring and mini-

mizing methane leakage from natural gas infrastructure built in the region.

2

Background and Context

Natural gas is the third-largest source of primary energy worldwide, behind oil and coal.1 It is also

the world’s largest source of heat.2 Homes and businesses use natural gas for space and water heat-

ing; and industrial processes, including the manufacturing of plastics, pharmaceuticals, and glass,

often rely on heat produced from the combustion of natural gas.3 Natural gas is also used to gener-

ate electricity, and globally, gas-fired power plants are the second-largest source of power, behind

coal.4

Gas brings several advantages compared with other fossil fuels. Burning natural gas—for heat-

ing or power generation—emits far fewer pollutants that cause local air pollution and half as much

carbon dioxide as coal.5 Additionally, natural gas can make it easier to integrate renewable sources

into the grid, because gas-fired turbines used to produce power can vary their output easily to

compensate for unpredictable wind and solar power.6 As a result, natural gas can facilitate a transi-

tion to zero-carbon energy infrastructure.

But natural gas also has disadvantages. It has a lower energy density—the amount of energy

stored per unit volume—than oil or coal, which makes the transport of gas expensive and capital

intensive. Costly pipelines are required to transport natural gas in its gaseous phase, and even cost-

lier facilities are needed to transport it around the world in its liquid phase, including facilities to

condense the gas at ultralow temperatures and dedicated tankers to transport newly liquefied natu-

ral gas (LNG). In addition, storage of gas to meet seasonal or daily demand fluctuations is more

expensive than that of other fossil fuels, as it requires the use of depleted oil or gas fields, under-

ground salt domes, or LNG storage tanks.7 These factors have historically limited the economic

competitiveness of gas against coal and oil.

Because of its high energy density and transportability, oil is likely to remain the dominant fuel

source for the transportation sector. But for stationary heating and power generation, gas could be

cheaper than coal. Over the last half century, gas has become increasingly attractive, and its use

around the world has steadily increased. In the early 1970s, gas accounted for only 18 percent of

the world’s primary energy demand.8 Oil market volatility in that decade led governments to pro-

mote the use of gas over other fuels. In the power sector, in particular, gas use almost tripled from

1973 to 1990. Then, as a more efficient gas-fired power plant design—the combined-cycle gas tur-

bine—became more popular, gas use in the power sector doubled between 1990 and 2010.

Now, the newfound global abundance of gas has made the fuel even more economically compet-

itive, and trade in gas is thriving (see box 1). The International Energy Agency (IEA) projects that

by 2020, global gas supply will increase by 160 billion cubic meters (bcm), over the current total of

3,640 bcm.9 This is because new technologies have made it possible to extract gas from unconven-

tional sources—including shale, coal-bed methane, and tight gas—at a reasonable cost. For exam-

ple, in the United States, firms are using hydraulic fracturing—or fracking—and horizontal drilling

to extract gas from shale deposits that were once considered uneconomic to drill. As a result, shale

gas production in North America grew from around 30 bcm in 2005 to over 400 bcm in 2015.10

3

Facing saturated demand at home, U.S. gas producers have begun exporting LNG abroad. The U.S.

Energy Information Administration projects that net U.S. LNG exports could climb to 124 bcm in

2040 from under 5 bcm today.11 Elsewhere, Australia’s LNG exports could rise to over 130 bcm

from 40 bcm today, driven partly by its production of coal-bed methane.12 Other major supply in-

creases could come from Iran, Qatar, and Russia.13

Firms and governments around the world have made considerable investments in export termi-

nals to liquefy and ship LNG; the IEA recorded fifteen LNG projects under construction as of

2016, with a total annual capacity of 150 bcm, with deliveries scheduled to begin between 2016

and 2018.14 Complementing this trend, twenty-nine regasification facilities to import LNG, repre-

senting around 107 bcm of total capacity, are under construction. Of these, twenty-one are located

in the Asia-Pacific region, representing almost 70 percent of total import capacity under construc-

tion.15

Box 1. A Primer on Natural Gas Trading

Because of the costly infrastructure required to transport natural gas, its trade has historically

lagged behind that of other fossil fuels such as oil. But in recent decades, global trade in gas has

risen rapidly, and by 2015, one-third of all extracted natural gas was sold outside the country of

extraction.16 Today, trade via pipeline accounts for 68 percent of total gas trade; Canada, Norway,

and Russia account for 54 percent of pipeline gas exports, and Germany, Italy, and the United

States account for 32 percent of imports.17 Trade in LNG represents the remaining 32 percent of

traded gas.18 Australia, Malaysia, and Qatar account for 53 percent of LNG exports, and China,

Japan, and South Korea account for 56 percent of imports.19 Overall, trade in gas is projected to

grow 45 percent by 2026, with LNG accounting for two-thirds of this growth, fueled by an almost

60 percent surge in global LNG supply over the next decade.20

Historically, there has not been a single global market for trading natural gas as there is for oil.

Rather, there is a disparity in the regulations and pricing conventions among different regional

markets. In the Asia-Pacific, where 38 percent of gas is imported via long-distance LNG shipping,

the price of gas is most commonly linked to the price of oil.21 Oil-linked pricing is a relic of earlier

times when gas was primarily viewed as a competitive fuel for heating, power generation, and in-

dustrial applications. In Asia, long-term contracts often prohibit gas from being resold to third

parties (through destination clauses) or compel buyers to pay for contracted supplies they do not

take (through take-or-pay contracts). By contrast, the North American gas market relies on gas-

on-gas, or hub-based, pricing to enable buyers and sellers to efficiently transact and update the

market price of gas based on changes in supply and demand. This market is made possible by flexi-

ble regulations and an extensive network of pipelines, storage facilities, and LNG facilities that

converge in Louisiana’s Henry Hub, where a single market price is set and constantly updated.

Over the last several years, the European gas market, which used to function like its rigid, outdated

Asian counterpart, has moved toward gas-on-gas pricing like the North American market.

O P P O R T U N I T Y F O R G A S T R A D E I N T H E A S I A - P A C I F I C

Asian countries could be the biggest beneficiaries of the increasingly attractive natural gas. Alt-

hough gas has historically been more expensive than coal, increased global LNG supplies, along

4

with lower oil prices, have lowered prices in the Asia-Pacific.22 In addition to lowering their energy

bills, countries that increased their gas consumption would benefit from a diversity of supply and

less air pollution. More gas use in Asia would mean that GHG emissions would fall as gas dis-

placed coal. However, to take advantage of the gas opportunity, Asian countries will need to invest

in gas infrastructure and discontinue regulations that inhibit gas trading. Countries in Europe and

North America have acted decisively in the past to capitalize on a glut in gas supply, and the Asia-

Pacific could now do the same.

Lessons From Europe and North America

In both Europe and North America, gas oversupply has helped liberalize gas markets to take ad-

vantage of a newly affordable energy source. Similar to contracts in the Asia-Pacific today, North

American gas contracts through the 1970s were long-term arrangements in which prices were

heavily regulated or indexed to oil prices, and destination clauses restricted the resale of gas. These

contracts became unpopular in the 1980s when U.S. supply overtook demand. Pipeline companies

found themselves over-contracted for high-priced supplies that had been secured when gas was

scarce, just as their customers were looking to purchase cheap supplies in the emerging spot mar-

ket, where gas could be purchased for immediate delivery.23

Such a free market began to emerge in the mid-1980s, thanks to regulatory reforms passed by

the U.S. Congress. These reforms decontrolled the price of gas, unbundled interstate pipeline

companies, and required those companies to allow open access to their pipelines so that any local

gas distribution company could purchase gas from a faraway producer and pay for pipeline capaci-

ty to transport it. This brought gas prices down, encouraged greater use of gas, and ultimately

stimulated investment in gas infrastructure to serve rising demand. The private sector has since

invested heavily in developing gas supplies and building long-distance pipelines. These pipelines

are not confined to the United States; pipelines built between the United States and both Canada

and Mexico have resulted in a booming transcontinental gas trade. Across the continent, prices are

set relative to the price that traders can obtain at the Henry Hub in Louisiana, where nine interstate

gas pipelines converge.24 Thanks to enabling regulations and infrastructure, the United States has

increased its use of natural gas by 58 percent in the last thirty years, from roughly 489 bcm to 773

bcm.25 The flexible market has made U.S. supply resilient to major supply disruptions, as demon-

strated in the aftermath of Hurricane Katrina in 2005, when gas was redirected to wherever de-

mand was the strongest.

Europe has more recently moved to liberalize its gas market. While the United States was enact-

ing regulatory reforms in the 1980s, Europe still traded gas under long-term, bilateral, and inflexi-

ble contracts. But by the end of the decade and into the 1990s, after supply surged—from North

Africa, Norway, Russia, and the United Kingdom—the UK led the liberalization of its own market

and the European gas market.26 The UK connected its gas infrastructure to that of continental Eu-

rope to export surplus gas. And over the next two decades, the European Union (EU) and its con-

stituent governments passed regulations to unbundle vertically integrated gas suppliers, harmonize

regulations across borders, remove barriers to cross-border trade, and allow third-party access to

pipelines. On top of this, European governments and the private sector invested heavily in pipe-

lines, storage infrastructure, and LNG facilities. National gas regulators across Europe cooperated

to develop and operate a pan-European gas grid. As a result, hub-based pricing—based on hubs in

Germany, the Netherlands, and the UK—became increasingly popular in Europe, dominating gas

5

sales in the UK and slowly gaining ground from oil-indexed pricing in continental Europe. The

EU’s slow but steady energy market liberalization has improved Europe’s collective energy securi-

ty by diversifying supply away from Russia.

The Development of Natural Gas Markets in the Asia-Pacific

The Asia-Pacific’s limited use of gas, its inflexible markets, and the impending oversupply of LNG

all suggest that the region is in the same place that Europe and North America were decades ago

when they embraced gas. If Asian countries enacted regulatory reforms and invest in infrastruc-

ture, they could create a hub-based trading system that enables them to rapidly expand their con-

sumption of cheap gas.

Asia’s gas market originated in Japan, which began importing LNG in 1969 to diversify an ener-

gy mix dominated by oil. In subsequent decades, gas trade rose in the Asia-Pacific, but, in contrast

to the United States and Europe, trade within the region consisted almost entirely of LNG rather

than pipeline gas.

Japan continued to drive Asia’s gas demand through the 1990s, and its vertically integrated

power utilities preferred to source gas from elsewhere in the Asia-Pacific, including Australia, Bru-

nei, Indonesia, and Malaysia, as well as Russia. By pioneering seaborne gas trade, Japan set the

conventions that still characterize the modern Asian market. Japanese utilities secured gas supplies

through long-term, oil-indexed contracts with destination clauses restricting the ability to shift

cargoes from the contracted buyers. Both buyers and sellers considered long-term commitments

and predictable prices essential to underwrite the massive infrastructure required for the LNG

trade.27 In the 2000s, China took over as the driver of Asian gas demand as urban homes and facto-

ries switched to gas; the country increased consumption from 50 bcm in 2005 to 180 bcm in

2014.28 Still, oil-indexed contracts pioneered by the Japanese persist across the Asia-Pacific.29

Recently, gas oversupply is stimulating changes in the way gas is traded in Asia, in a manner

similar to what happened in Europe and North America. Even though LNG trade among countries

in the Asia-Pacific retains oil-indexed contracts, U.S. LNG exporters, which entered the region in

2016, have adopted a more market-oriented pricing approach. They are charging Asian buyers

prices that depend on the Henry Hub price, with the costs of liquefaction and shipping added in.

Since Henry Hub prices are much lower than those in traditional Asian gas contracts, this new ap-

proach could undercut oil-indexed contracts and support the emergence of a spot market for Asian

gas trade.30 Moreover, even contracts among Asia-Pacific countries are becoming more flexible,

through shorter terms and fewer rigid destination clauses.31 New suppliers are seeking to under-

mine the privileged position of existing suppliers and their long-term, rigid, and oil-indexed con-

tracts. Since LNG cargoes can be easily rerouted to match changing demand patterns—unlike

pipelines that link fixed locations—flexible LNG markets could make it easier for both buyers and

sellers to diversify their trading partners.

If economic pressure continues to undermine rigid contracts, and if Asian countries enact regu-

latory reforms and invest in infrastructure, gas consumption in the Asia-Pacific could rise dramati-

cally. Although China is Asia’s largest consumer of gas, gas only accounts for 5 percent of China’s

energy demand. Similarly, gas only accounts for 5 percent of energy demand in India, and despite

its skyrocketing energy needs, growth in India’s gas consumption is flat.32 Gas could meet the

needs of Asia’s large and growing economies while providing significant associated benefits. By

tapping into the vast pool of new LNG supplies from all over the world, Asian countries could di-

6

versify their energy supplies and enhance their energy security. A more flexible and liquid gas mar-

ket would also reduce the market power exercised by any one producer. In addition, the replace-

ment of coal by natural gas can ameliorate local pollution—a major public health issue in many

cities in the Asia-Pacific—thanks to the lower levels of sulfur, mercury, and nitrogen oxide released

from burning natural gas. Increased use of natural gas will make it easier for Asian countries to cur-

tail their GHG emissions and meet international climate commitments; without embracing gas,

such achievements will be nearly impossible.33

A C L O S I N G W I N D O W

The window of opportunity for the Asia-Pacific to embrace natural gas is unlikely to stay open for

long. If Asian countries fail to make infrastructure investments or enact regulatory reforms while

prices are low, it is unlikely that they will begin investing when prices spike. Such a spike, counter-

intuitively, is exactly what could happen as a result of increasing gas market oversupply.

Natural gas exports are spiking globally, but demand is not keeping pace even as overall energy

consumption grows. Although North America accounts for the most demand in the world—

consuming 950 bcm annually—the IEA projects that the demand will grow tepidly, if at all, espe-

cially as renewable energy additions outpace gas use in the power sector.34 In Europe, gas use—

roughly 433 bcm per year—has not yet recovered to pre-2008 levels and will likely only increase

modestly.35 Within the Asia-Pacific, developed economies such as Japan and South Korea consume

240 bcm annually—half of all regional LNG trade—but that figure could fall, especially if Japan

can successfully restart its nuclear reactors and displace gas-fired power generation.

That leaves emerging Asian economies, accounting for 300 bcm annually, as the possible source

of gas demand growth, but those economies are poised to disappoint as well. In 2015, China’s gas

demand grew by only 4 percent, in contrast to the 15 percent growth it experienced over the previ-

ous five years. In India, gas demand could grow by 6 percent annually, but that forecast is uncer-

tain. Gas demand in Latin America and the Middle East might grow but with only a modest effect

on global demand. Altogether, the IEA projects that global demand might grow by 140 bcm by

2021, compared with 160 bcm of new global production.36

So far, this oversupply has caused gas prices to fall. As a result, the private sector has already be-

gun scaling back on investments in infrastructure to produce, store, and transport gas. This trend is

reminiscent of the oil market in the 1990s, when low prices dissuaded companies from investing in

new sources of production. By the 2000s, demand outpaced supply and oil prices rose relentlessly

for a decade. A similar boom-bust cycle could be on the horizon for the gas market. Low gas prices

are deterring upstream producers from exploration, and globally, new investments in infrastruc-

ture to export LNG halted in 2016. Whereas the current oversupply is the result of decisions made

over the last decade to invest in gas production and infrastructure, falling investment flows today

could send the market into a shortage within the next decade, resulting in increasing prices as

boom turns to bust.

Such a price spike would undermine the ability of countries in the Asia-Pacific to make substan-

tial infrastructure investments to increase their consumption of gas. These investments include

building national pipeline grids to distribute gas to urban centers where demand potential is the

greatest as well as connecting with pipelines in neighboring countries to enable a flexible regional

gas market. Still, unlike in North America, a single market hub where most pipelines intersect is

unlikely to form in Asia because Asia’s regional gas trade relies much more heavily on LNG. In-

7

stead, a strong Asian gas trading market could have several hubs, as in Europe, with each hub’s

price linked to others’ but differing by the costs of shipping LNG. To realize this vision, terminals

to import and regasify LNG are crucial to increasing imports of newly abundant LNG. Further, gas

storage facilities are necessary to buffer seasonal swings in gas demand—for example, from heat-

ing or from the power sector—and to enhance energy security. But if gas prices rise, other fuels

such as coal will become more attractive, depressing the investment climate in gas infrastructure

and discouraging governments from promoting gas use.

If gas is considered expensive and uncompetitive, governments are unlikely to prioritize market

reforms needed to speed gas adoption. For example, Asian countries need to require third-party

open access to pipelines and LNG terminals and remove gas price controls in order to enable gas

trading and the emergence of accurate, responsive, and transparent market prices at each of several

hubs, based on the fundamentals of supply and demand. Only through such reforms can the region

gain access to flexible and secure supplies of affordable gas. So long as Asian gas demand—

especially in emerging economies—stagnates, global oversupply is in danger of rapidly giving way

to a supply shortage and a spike in prices, and the Asia-Pacific will lose its opportunity to embrace

gas.

8

How Asia Could Power a Sustained Increase in Gas Demand

Emerging Asian economies need a prolonged period of abundant and affordable gas supply for

firms to make profitable infrastructure investments and for governments to enact enabling re-

forms. At the same time, the Asia-Pacific needs to step up its demand for gas suppliers around the

world to invest in supply infrastructure. No other region has economies that do not already rely

heavily on gas or are dynamic enough to boost demand to balance an oversupplied market. There-

fore, with Asian demand currently flagging, suppliers are pulling back and priming the market for a

shortage and price spikes.

It falls to the Asia-Pacific to self-start a sustained increase in demand. A sufficient uptick in

Asian gas demand could stabilize gas markets long enough for the countries in the region to build

infrastructure and enact regulations to gradually increase gas use. Determining if and how this

might be possible requires, first, projecting the most likely trajectory for Asian gas demand and,

second, identifying the countries that could plausibly increase their demand over those projections.

P R O J E C T I N G T H E B A S E L I N E S C E N A R I O

To develop a baseline projection for gas demand in the Asia-Pacific, the Nexant World Gas Mod-

el—as implemented by the Energy Studies Institute at the National University of Singapore—is

used to project future natural gas supply and demand around the world (see appendix). The data

used by the model is based on the 2015 New Policies Scenario in the IEA’s World Energy Outlook

and takes into account the effects of energy policies and pledges made by governments globally—

even if they have not yet been implemented—on energy supply and demand. Assumptions about

population changes and macroeconomic performance are taken from data from the United Na-

tions, the Organization for Economic Cooperation and Development (OECD), the International

Monetary Fund, and the World Bank. Assumptions about end-user fuel prices in the baseline sce-

nario come mostly from time-series data for coal, oil, gas, electricity, heat, and biomass, drawn

from the IEA’s database on energy prices and taxes.37 The resulting model projections for demand

for different fuels is disaggregated by sector for each country, yielding demand estimates for na-

tional industry, transport, residential, services, and agricultural sectors.38

Although the baseline projection of global gas demand reveals growth over the next decade, the

increase is not enough to match the enormous supply projected to become available in the next five

years. Consistent with the IEA data from which the baseline scenario is derived, the model predicts

that demand for natural gas will increase from 3,500 bcm in 2014 to 4,100 bcm in 2025, with

much of the projected growth in global gas demand centered on the Asia-Pacific region, specifically

China and India.39 Natural gas demand from China, for example, increases annually by 7.8 percent

on average in the baseline scenario. Demand in India is projected to increase at 7.1 percent, alt-

hough from a much lower base.

9

The model projects that the increase in demand would be served by incremental supplies from

Australia, the Middle East, North America, Russia, and Caspian countries (Armenia, Azerbaijan,

Georgia, Kazakhstan, Kyrgyzstan, Tajikistan, Turkmenistan, and Uzbekistan) (see figure 1).40 This

gas is projected to be transported via pipelines and sea. Pipeline gas transport is expected to in-

crease from 2,020 bcm in 2015 to 2,660 bcm in 2025, while seaborne LNG exports would rise

from 330 bcm in 2015 to 550 bcm in 2025.

Figure 1. Global Natural Gas Supply by Region in Baseline Scenario

Source: Authors’ estimation from the model.

Breaking down these numbers can set baseline expectations for gas flows around the world and

make it possible to discern geopolitical effects of a potential uptick in Asian demand and resultant

shifts in global flows. In the baseline scenario, one-third of the increase in LNG trade would come

from a thirty-fold increase in U.S. LNG exports, which would be destined for Europe, India, Japan,

and South Korea. India’s reliance on LNG in particular means that Australia, the Middle East, and

North America would benefit from the projected increase in Indian demand, with the majority of

LNG coming from the Middle East. By contrast, in China, the incremental increase in gas demand

under the baseline scenario would be met by a mix of pipeline gas and LNG imports. Pipeline im-

ports to China—mostly from Russia and Caspian countries—would increase from just over 50

bcm in 2016 to 126 bcm by 2025. China’s LNG imports, on the other hand, would only grow from

38 bcm in 2016 to 50 bcm by 2025, mostly from Australia, the Middle East, and Southeast Asia,

and, from 2020 onward, from Papua New Guinea and Russia.

I D E N T I F Y I N G I N C R E A S E I N D E M A N D F R O M C H I N A A N D I N D I A

Having defined the baseline scenario of gas demand, the next step is to identify the most plausible

source and magnitude of an increase in Asian gas demand. Expectations of future gas supply and

demand can change unpredictably. The rise of unconventional gas production transformed North

10

America’s gas prospects. On the demand side, China emerged as a significant consumer of gas rap-

idly, with demand increasing from 28 bcm to 188 bcm between 2000 and 2014, before the recent

slowdown that threatens global gas market stability. A similar increase in gas demand over the

baseline projection could most plausibly come from the Asia-Pacific, which is projected to account

for over two-thirds of global energy demand through 2025.

A three-part test can narrow down where that increase could come from. First, a demand in-

crease significant enough to help stabilize global markets would only come from a large economy,

which narrows the scope to China, India, Japan, South Korea, and Thailand. The Association of

Southeast Asian Nations (ASEAN) treated as a single unit could be a significant source of future

gas demand, but energy market decisions remain almost wholly under the domestic control of

ASEAN members. Therefore, this analysis does not consider ASEAN as a single demand center.

Second, a candidate economy should be growing, thus requiring incremental energy supplies.

Third, the economy should not already have achieved a high degree of gas penetration to enable

gas, rather than another fuel, to fulfill the increase in energy demand. This test narrows down the

sources of increased future demand to China and India, ruling out Japan, South Korea, and Thai-

land (see table 1). Japan, for example, is the second largest gas market in the Asia-Pacific, but Ja-

pan’s already-high per capita income, low economic growth, declining population, and potential

substitution from gas to nuclear power in the coming years make it highly unlikely that Japan’s gas

demand will increase considerably by 2025.

11

Table 1. Natural Gas Demand in the Asia-Pacific

Source: BP Statistical Review of World Energy 2015.

Unlike Japan, China and India are developing countries with huge populations. They also have

large projected future energy demand and infrastructure investment needs. Looking to 2025, for

example, China and India account for 53 percent of the increase in global energy demand. At pre-

sent, gas is a relatively small part of their energy use—5 percent each for China and India. By con-

trast, the share of gas in energy demand is around 28 percent in the United States and around 25

percent in Europe.

12

Although gas demand in both China and India grow in the baseline projection by 7 to 8 percent

annually—doubling by 2025 with increases of 190 bcm and 45 bcm, respectively—there is poten-

tial for much higher growth. Even if Chinese and Indian gas demand increased 25 percent beyond

the baseline projection, gas use as a proportion of total energy demand in these countries would

still be at levels well below those of OECD countries, implying substantial latent gas demand in

both countries.

The power sectors of the two countries offer the most scope for increasing gas demand. For ex-

ample, gas is the energy source for little more than 4 percent of Indian electricity generation, with

some 28 gigawatts of gas-fired capacity that is chronically underutilized—the capacity factor is 24

percent—despite massive unmet power demand, especially at peak load times. China has a similar

situation.

Raising utilization rates for existing and planned power generators would be desirable for both

countries and would deliver increased power supplies with much lower pollutant levels compared

with coal. It would also buffer and help integrate intermittent wind and solar energy. In India, any

increase in power capacity is welcome, given the quarter of a billion people without access to elec-

tricity supply and chronic gap between power supply and demand. If both China and India raised

even existing power plant utilization to 50 percent, gas demand in the power sector alone would

increase by about 25 bcm and 18 bcm, respectively; this means respective increases in gas demand

of 13 percent and 40 percent over the incremental increase in the baseline projection. In China, the

projected increase in demand could be more than doubled by including the potential for increased

use of gas for heating in factories and urban homes. Altogether, 25 percent increases over the base-

line projection for gas demand growth are plausible for both China and India and would result in

overall gas use that would still be surpassed by OECD averages.

Nevertheless, there are obstacles to increased gas use in China and India. The Chinese govern-

ment is wary of increased reliance on natural gas, which would increase dependence on imports. In

India, financially embattled power distribution utilities struggle to procure sufficient power from

generators, which makes it difficult for gas plants to increase their output; moreover, expensive

import terminals for LNG are needed to bring in new gas supplies, but domestic project finance is

scarce. Neither country has energy and power markets that give gas-fired power generators an ad-

vantage over coal, unlike in the United States. Moreover, in both countries, price ceilings on the

sale of natural gas discourage private sector investment in the infrastructure to import and

transport gas.

Yet, both countries’ governments have demonstrated interest in increasing natural gas use. Chi-

na’s thirteenth five-year plan calls for switching from coal to gas, and India’s Prime Minister Nar-

enda Modi has prioritized the shift to a natural gas economy.41 If policy shifts in China and India

improve the investment climate for gas, demand could rise above the baseline projections. That

incremental demand is unlikely to be met by local supply, as both China and India have struggled to

boost domestic production.42 Thus, China and India could plausibly increase their gas demand by

25 percent through 2025 over the baseline projection.

13

Insights From Simulating an Increase in Asian Gas Demand

With the source and magnitude of a potential increase in Asian gas demand over the baseline pro-

jection established, the final step is to rerun the model to see if China and India could successfully

stabilize global gas markets by bringing global gas prices to levels high enough to sustain invest-

ment in new supply and export infrastructure yet sufficiently low to keep consumption affordable.

This would keep the window of opportunity open for the Asia-Pacific to embrace natural gas. The

model results can also reveal which suppliers are likely to benefit the most from an increase in

Asian gas demand and the potential geopolitical implications.

Rerunning the model entails retaining the same assumptions—including supply sources, supply

infrastructure, and pricing—and evaluating the effects of a 25 percent increase in Chinese and In-

dian gas demand over the baseline scenario for global gas prices and flows from 2020 through

2025.43 The difference in projected gas demand under the baseline scenario compared with the

increased Chinese and Indian gas demand scenario is shown in figure 2. By 2025, collective Chi-

nese and Indian gas demand would increase from 529 bcm to 670 bcm, with China accounting for

81 percent of the incremental amount.

Figure 2. Scenarios for Natural Gas Demand Increases in China and India

Source: Authors’ estimation from the model.

14

E F F E C T S O F H I G H E R D E M A N D O N G L O B A L G A S F L O W S

Feeding in both scenarios and comparing the model output yield projections for which gas produc-

ers would benefit the most from the increase in Asian gas demand. Figure 3 plots the change in

each global supplier’s gas production relative to the baseline case. A marked increase in Chinese

and Indian gas demand is projected to be met through imports rather than by producers in the two

countries, where only limited supplies of unconventional gas could be tapped economically before

2025.

Figure 3. Modeled Changes in Global Gas Production, Relative to Baseline

Source: Authors’ estimation from the model.

Of the global producers that serve the incremental demand from China and India, Russia bene-

fits the most. Its projected gas production increases by a cumulative total of 200 bcm over the

2015–2025 period, with mean annual production of 885 bcm compared with 667 bcm in the base

case. Australia and Caspian countries, with production increased by 87 bcm and 100 bcm, respec-

tively, would also gain. North America, on the other hand, would experience little production

change between the two scenarios, although it would produce the largest volumes of gas through-

out the forecast period, buoyed by the size of domestic markets.

Russia’s production could increase so sizably because its pipeline exports to China are projected

to account for one-third of China’s incremental demand. Russian exports would begin in 2020

with the opening of the Power of Siberia pipeline and grow slowly through 2025 (see figure 4).

The utilization rate of import pipeline capacity into China is close to 100 percent over the forecast

period, demonstrating the superior economics of these projects compared with LNG trade with

China. However, because pipeline capacity is limited, the remaining two-thirds of China’s incre-

mental demand is projected to be met by LNG imports, 87 percent of which would come from

Australia, Indonesia, and Malaysia.

15

Figure 4. Modeled Changes in LNG Exports to China by Supplying Region, Relative to Baseline

Source: Authors’ estimate from the model.

In contrast to Chinese demand, Indian incremental gas demand is projected to be met solely

through increased LNG imports, owing to the absence of additional import pipeline capacity with-

in this time frame. Incremental LNG supplies are projected to originate in sub-Saharan Africa (46

percent) and the Middle East (54 percent); North American LNG exports to India would not in-

crease because of disadvantageous freight costs.

In addition to increased Russian pipeline exports, the other major effect of a potential increase

in Chinese and Indian gas demand would be a reorganization of LNG trade flows within the Asia-

Pacific and globally. LNG cargoes from Australia and Southeast Asia would be diverted from Ja-

pan, South Korea, and South Asia to reach China, which would be paying higher prices. Altogeth-

er, the two exporters would increase their shipments to China by nearly 200 bcm and reduce their

exports to the rest of the region by a similar amount. North American suppliers would help fill the

gap, most notably by increasing exports to Japan and South Korea by over 15 bcm (see figure 5).

The secondary effect is that North American LNG exports to Europe are projected to decline as

gas increasingly flows toward the higher-priced Asia-Pacific markets.

These changes in global gas flows, as a result of increased Asian gas demand over the baseline

project, could compromise U.S. foreign policy interests. The increase in production would give

Russia an economic boost, thus weakening the efficacy of U.S. economic sanctions and strengthen-

ing Russia’s hand in situations in which its stance conflicts with U.S. interests, such as its ongoing

military operations in Syria or prior operations in Ukraine. Moreover, the reduction in U.S. LNG

exports to Europe could expose U.S. allies to higher levels of import dependence on Russia.

Notably, however, even though overall U.S. exports do not increase significantly, the shift of

U.S. cargoes toward Asian countries such as Japan and South Korea could strengthen economic

ties between the United States and its allies. Increased U.S. gas exports to Asia, priced via flexible

contracts, could continue to erode the rigid Asian gas markets, opening new opportunities for the

United States and enabling a more diverse market with multiple supply sources for Asian coun-

tries.

16

Figure 5. Modeled Changes in North American LNG Exports by Destination, Relative to Baseline

Source: Authors’ estimation from the model.

E F F E C T S O F H I G H E R A S I A N G A S D E M A N D O N G L O B A L P R I C E S

Despite potentially strengthening Russia’s gas market position, an increase in Asian gas demand

would likely advance U.S. interests overall by stabilizing the global gas market and paving the way

for a long-term demand increase in Asia, which is a lucrative market for U.S. gas exports. In addi-

tion to predicting shifting flows, the model projects stable and moderately higher gas prices that

justify continued global investment in gas supplies and infrastructure, thanks to an increase in

Asian gas demand.

Figure 6 shows the change in selected gas prices relative to the baseline scenario. Overall, the re-

sults show that a 25 percent rise in consumption in China and India would lead to wholesale price

increases in markets outside Australia and North America. Gas spot prices would rise on average

by $1.5 per million British thermal units (mmBtu) in China and by $0.8 per mmBtu in India. As a

result of reorganized Asia-Pacific trade flows, Japanese and South Korean prices are projected to

rise by $1.5 per mmBtu, relative to the baseline; European prices should also increase. The link

with crude oil prices in many current contracts means that the projected price path is influenced by

assumptions about the future path of oil prices, which is unpredictable. This analysis uses the

World Bank’s forecast to 2025, with gas prices calculated as a function of lagged oil prices for oil-

indexed contracts, given that many contracts are priced one or two quarters in lag with oil prices.

Brent prices are projected to steadily increase into the $80 per barrel–range in 2025.

17

Figure 6. Modeled Changes in Natural Gas Prices by Region, Relative to Baseline

Source: Authors’ estimation from the model.

The model results suggest that natural gas spot prices would increase by more than 20 percent

even with a modest 3 percent increase in global demand, from the assumed increases in Chinese

and Indian gas demand. This suggests that an increase in demand from these two countries could

lead to significant price increases in import nations in the Asia-Pacific. These price increases

should be sufficient to reverse the trend of global gas suppliers withdrawing investment in new

production or infrastructure to export gas. Yet, a 20 percent increase in gas prices is not enough to

erase the attractive economics of gas compared with coal—for example, with respect to power

generation—that will be needed for Asian countries to embrace gas and enjoy the attendant bene-

fits of energy security, decreased air pollution, and lower GHG emissions. (That is not to downplay

the importance of environmental regulations limiting the uptake of coal, which can speed the tran-

sition toward natural gas over and above the rate induced by the favorable economics of natural

gas.) In other words, the 25 percent increase in gas demand from China and India—a plausible

change from the baseline projection—is a Goldilocks boost to global demand that could stabilize

gas markets and make both production and consumption economically attractive.

North American exporters—predominantly those based in the United States—are critical in

moderating this increase in prices from a comparatively small increase in Asian gas demand. These

producers collectively act as swing suppliers, shifting gas from Europe to more profitable markets

in the Asia-Pacific, particularly China, Japan, and South Korea. Thus, while U.S. exports of cheap,

unconventional gas are only a small share of global gas use, they have a disproportionate effect on

markets, pitting Asian and European consumers against one another in a competition for those

supplies, leading to the rerouting of cargoes in response to small demand changes, and promoting

global integration of markets. Although there are substantial price differences among the different

regions where gas is traded, prices should start to converge by 2025 because of the competition

between the Asia-Pacific and the rest of the world for flexibly priced and traded North American

LNG.

18

Recommendations

Increasing Asia’s demand for natural gas—first by just enough in China and India to stabilize glob-

al markets, then ultimately in a substantial and sustained way that displaces coal use and opens new

markets—advances U.S. interests. Whether gas demand in China and India will exceed baseline

projections over the next decade depends on the countries’ domestic policies. To encourage such

an outcome, the United States should provide technical assistance and urge multilateral financial

institutions like the World Bank to also provide financial assistance. At the same time, the United

States should help the broader region transition toward a hub-based gas market to lay the ground-

work for a sustained increase in regional gas demand. Further, recognizing that gas only mitigates

climate change insofar as it offsets GHG emissions resulting from consumption of coal, the United

States should provide technical assistance to Asian countries to minimize leakage of methane and

other gases.

E N C O U R A G E C H I N E S E A N D I N D I A N E F F O R T S T O I N C R E A S E G A S

C O N S U M P T I O N O V E R T H E N E X T D E C A D E

Both China and India will need to invest in gas infrastructure and reform their internal gas markets

to increase their consumption of gas over baseline projections. The Indian government should fast-

track permits for additional LNG import terminals across the country, new pipelines for a national

gas grid, and strategic storage facilities to protect against supply disruptions. Public financing or

credit enhancements could supplement private sources of infrastructure funding. In addition, the

government should reform the gas industry and create a liberalized market by, for example, un-

bundling gas transportation from retail and removing price controls. In China, the government

should improve access to imported gas outside Beijing and Shanghai by constructing LNG termi-

nals and pipelines. Currently, in twenty-two out of China’s thirty-one regions, less than 40 percent

of the population has access to gas. The Chinese government should also reform the way gas is

sold, particularly by removing administrative price controls on the price of gas-fired electricity

generation, which is a valuable buffer for intermittent renewable energy generation and should

increase if compensated fairly.

In India, removing price controls is politically fraught because large industrial gas consumers

(e.g., in the fertilizer sector) exert influence to maintain an illiberal gas sector. In China, the coal

power sector prevents gas-fired generators from receiving higher revenues for providing peaking

power to compensate for variable renewable energy. While these domestic political considerations

lie largely outside of U.S. influence, there is cause for optimism: India, for example, has, over the

last two years, incrementally reformed its gas prices and taken steps to increase gas use in the pow-

er sector.

The United States has succeeded, through regulatory reform, in sparking investments in infra-

structure and developing a liberal market that has supported a sustained increase in gas consump-

19

tion. Therefore, it should sponsor technical exchanges with China and India, sending officials from

the U.S. Federal Energy Regulatory Commission, which oversees the domestic gas sector, and the

Department of Energy, which oversees exports and imports of LNG, to share their expertise. Such

efforts need not be limited to these two countries, but they are important priorities given the large

potential for increase in gas demand. In addition, given U.S. influence over the governance of mul-

tilateral financial institutions such as the World Bank, the United States should advocate for these

institutions to provide financial assistance for gas infrastructure projects, especially in India to in-

crease its capability to import and use LNG. Moreover, the United States should continue to urge

China and India to pursue more ambitious targets for reducing GHG emissions, which would be

well served by adopting gas, in tandem with renewables, as a replacement for coal.

A D V I S E A S I A N C O U N T R I E S O N S E T T I N G U P H U B - B A S E D M A R K E T S

Besides supporting China and India in building up their gas demand, the United States should help

establish a thriving Asia-Pacific gas market that enables substantially higher consumption in the re-

gion. Private sector actors are already responding to changing market conditions in the Asia-Pacific

by increasing the use of gas contracts linked to globalized gas prices, such as the Henry Hub, and ena-

bling flexibility in destination clauses used in contracts. The United States has a crucial role in pro-

moting the development of a gas market in the Asia-Pacific based on transparency and nondiscrimi-

nation.

Although only a small share of global gas use, U.S. exports of LNG, based on gas-based pricing

and fully flexible in terms of destination, claim a relatively large share of trade in gas among regions

of the world—such as the Asia-Pacific, North American, and European regions—whereas many oth-

er producers tend to supply gas intra-regionally. Therefore, U.S. LNG exports can have an outsize

effect on the prices and flows of traded gas by competitively linking oversupplied regional markets.

In this sense, U.S. commitment to permit gas exports outside North America is an important policy

setting that provides both domestic and global benefits, especially in the Asia-Pacific region.

China, Japan, and Singapore are currently developing competing plans for hub-based mecha-

nisms to facilitate trading. Even if multiple trading hubs emerge, if they are connected within a sin-

gle market with uniform and transparent regulations, they could lead to regional gas market pric-

ing that links fundamental supply and demand across the Asia-Pacific. The European experience

suggests that coordinating initiatives designed to improve market functioning can help. Therefore,

the U.S. government, through the Department of State and other agencies, and in conjunction with

counterparts in the Australian government, should help regional governments coordinate regula-

tions for establishing a hub-based trading system in the Asia-Pacific. This coordination could occur

on a bilateral basis or through international organizations such as the Asia-Pacific Economic Co-

operation. In addition to examining the technical requirements for the establishment of a trading

hub, the United States should advise on issues such as third-party access to infrastructure in con-

sumer countries—notably LNG terminals and large gas pipelines—as well as the development of

appropriate regulatory institutions.

S H A R E B E S T P R A C T I C E S T O M I N I M I Z E M E T H A N E L E A K A G E

As the United States promotes gas use in the Asia-Pacific, it should seek to ensure that increased

emissions of methane, a potent GHG, do not offset the environmental benefits of switching from

20

coal to gas. Across the gas supply chain, from extraction to transportation and delivery, methane

can leak out of wells, pipelines, and storage containers. The U.S. Environmental Protection Agency

has developed best practices for minimizing the so-called fugitive methane emissions, and these

guidelines could help Asian countries avoid such emissions.

The Department of Energy and its national laboratories and the Environmental Protection

Agency should partner with gas producers such as Australia to provide technical assistance to

countries in designing their gas infrastructure in order to minimize leaks across the entire supply

chain. The United States should seek collaboration with the IEA to help disseminate these guide-

lines broadly. If Asian countries follow these best practices while creating thriving gas markets,

they can enjoy the benefits of a transition to natural gas while limiting global climate change.

21

Appendix: Technical Details

This paper uses a quantitative model to assess the implications of an increase in demand in China

and India on natural gas prices and on gas suppliers. In general, to understand the effect of such a

change, the authors compare the results of this simulated demand increase with a base-case scenar-

io developed by the Energy Studies Institute at the National University of Singapore.44 Demand

and supply projections in the base case are similar to those in IEA New Policies Scenario. In the

base case, global natural gas production capacity is set to increase from 3,884 bcm to 6,025 bcm

(1.77 percent compound annual growth rate [CAGR]) while demand increases from 3,584 bcm in

2015 to 5,077 bcm in 2040 (1.47 percent CAGR). This can be compared to the IEA reference case

estimate of 5,007 bcm in 2035.

The model incorporates all countries that produce or consume natural gas. Supply data is in-

cluded in the database as a cost curve for each producing country. The cost curves include a maxi-

mum production profile over time and cost of production. Production capacity and forecasting

data include all active and future or potential natural gas production fields in natural gas producing

countries. Annual production capacity, type of field, and marginal cost of production are the im-

portant parameters. The cost curves are made by aggregating reservoir production capacity and

marginal cost of production for each of the production fields in the country.

The model also incorporates infrastructure capacity constraints implicit in trade by pipeline,

LNG liquefaction facilities, and regasification and storage capacity, together with associated costs.

The infrastructure information includes information on location, start and end dates of operation,

source and destination, pipeline capacity, start and end dates of pipelines, and transportation tar-

iffs.

Trade is simulated through nodes, with less significant countries in the global gas market mod-

eled as single nodes, and larger countries, including Australia, Canada, China, Indonesia, Malaysia,

Russia, and the United States, divided into multiple nodes. Demand for each node is treated as ex-

ogenous in the simulation. The model balances supply and demand through the price mechanism

while minimizing gas procurement costs, which include both production and transport costs. Bal-

ancing is done on a quarterly basis, allowing the model to simulate the effects of variation in sea-

sonal demand.

Contracted and uncontracted flows of gas are also modeled in order to take into account the ef-

fect of existing contractual arrangements, such as contract clauses restricting destination. Of the

207 active LNG contracts in East Asia, only fourteen contracts are hub-based (Henry Hub or Na-

tional Balancing Point); one is mixed contract (Japan Crude Cocktail and Henry Hub), and the rest

are all oil (Japan Crude Cocktail). All pipeline contracts are indexed to oil derivatives, or heavy fuel

oil, in China. Thus, the model approximates the physical and contractual characteristics of the gas

market that shape trade.

Prices in the spot market are delivered-ex-ship prices. The model first calculates a shadow price,

defined as the marginal cost of procurement of gas to a specific country after optimizing the model.

22

This is determined by how tight the market is, as a function of supply conditions in the region, and

competing fuel prices. In the base case, competing fuels are oil derivatives and coal. This spot price

modeling means tighter markets lead to higher prices, constrained by alternate fuel costs. Over-

supplied market prices can go as low as the marginal cost of production. Hence, the spot price

range is constrained within these limits, with regional contract prices and oil prices affecting the

price level. Price changes in the model can be explained by changes in oil price, which has a signifi-

cant effect on the rise in prices in the 2016–2020 period, and changes in supply. Thereafter, the

price rise is moderated by increase in the market’s gas supply.

Data for demand is based on historical data on economic growth projections, energy intensity,

and population for the industrial, commercial, and residential sectors. Demand for major fuels that

compete with gas are also included in the model, with historical prices for both oil and coal taken

from the IEA’s energy prices and taxes database and adjusted to 2012 real-price levels. For supply,

nodes are characterized by annual production capacity, field type, and marginal production costs.

Thus, the marginal production costs for unconventional gas production is higher than those for

conventional fields. Historical gas prices reflect lagged oil prices for contracts that are indexed to

oil, an important feature given the role of oil-indexed gas prices in the Asia-Pacific region.

23

About the Authors

Ian Cronshaw is a visiting fellow at the Australian National University’s Crawford School of Pub-

lic Policy. Previously, he was a division head at the International Energy Agency, in charge of anal-

ysis of international gas, coal, and power markets.

Quentin Grafton is a professor of economics, public policy fellow, and director of the Centre for

Water Economics, Environment, and Policy at the Crawford School of Public Policy. He is a fellow

of the Academy of Social Sciences of Australia and the chair-holder of the UNESCO Chair in Wa-

ter Economics and Transboundary Water Governance.

Llewelyn Hughes is an associate professor at the Crawford School of Public Policy. He is the au-

thor of Globalizing Oil: Firms and Oil Market Governance in France, Japan, and the United States and

numerous academic and policy papers focused on energy policy in the Asia-Pacific.

24

Acknowledgments

The authors extend their deepest thanks to Hari Malamakkavu Padinjare Variam and Xunpeng Shi

of the Energy Studies Institute at the National University of Singapore for their assistance with the

discussion paper. The authors also thank two anonymous reviewers for helpful comments and

Varun Sivaram and Sagatom Saha for their work editing and producing the final document.

25

Endnotes

1. International Energy Agency, “Key World Energy Statistics,” 2016.

2. Anselm Eisentraut and Adam Brown, “Heating Without Warming: Market Developments and Policy Considerations for Renewa-

ble Heat,” International Energy Agency, 2014.

3. Union of Concerned Scientists, “Uses of Natural Gas.”

4. International Energy Agency, “World Energy Outlook 2016,” November 16, 2016.

5. Union of Concerned Scientists, “Environmental Impacts of Natural Gas.”

6. DeVynne Farquharson, “Beyond Global Warming Potential: A Comparative Application of Climate Impact Metrics for the Life

Cycle Assessment of Coal and Natural Gas Based Electricity,” Journal of Industrial Ecology, August 24, 2016.

7. Vivek Chandra, “Transport and Storage,” Fundamentals of Natural Gas: An International Perspective (Tulsa, Oklahoma: PennWell

Books, 2006), pp. 41–76.

8. British Petroleum, “BP Statistical Review of World Energy 2015 Workbook,” accessed December 12, 2016.

9. International Energy Agency, “World Energy Outlook 2016,” November 16, 2016.

10. U.S. Energy Information Administration, “Shale in the United States,” November 18, 2016.

11. U.S. Energy Information Administration, “Annual Energy Outlook With Projections to 2050,” January 5, 2017.

12. International Gas Union, “2016 World LNG Report,” April 12, 2016; Arif Syed, “Australian Energy Projects to 2049-50,” Aus-

tralian Bureau of Resources and Energy Economics, November 2014.

13. U.S. Energy Information Administration, “International Energy Outlook 2016,” May 11, 2016.

14. International Energy Agency, “Global Gas Security Review: How Flexible Are LNG Markets in Practice?,” 2016.

15. Ibid.

16. British Petroleum, “BP Statistical Review of Energy 2016,” p. 28, June 2016.

17. Ibid.

18. Ibid.

19. Ibid.

20. International Energy Agency, “World Energy Outlook 2016.”

21. British Petroleum, “BP Statistical Review of Energy 2016,” p. 28.

22. Victoria Zaretskaya and Scott Bradley, “Natural Gas Prices in Asia Mainly Linked to Crude Oil, But Use of Spot Indexes Increas-

es,” U.S. Energy Information Administration, September 29, 2015.

23. “Are We Headed Towards a Global Gas Market?” Enalytica, June 2015.

24. Jeff D. Makholm, “There Is But One True Hub, and His Name Is Henry,” Natural Gas and Electricity 32, no. 11, June 2016.

25. U.S. Energy Information Administration, “Natural Gas Consumption by End Use,” December 20, 2016.

26. Anthony J. Melling, “Natural Gas Pricing: Europe as the Battleground,” Carnegie Endowment for International Peace, 2010.

27. Warner ten Kate, Lászlo Varró, and Anne-Sophie Corbeau, “Developing a Natural Gas Trading Hub in Asia: Obstacles and

Opportunities,” International Energy Agency, 2013. 28. International Energy Agency, “World Energy Outlook 2016.”

29. Takeo Kumagai et al, “Japan’s Oil and LNG Price Evolution on the Path to Transparency,” S&P Global Platts, September 2016.

30. Ibid.

31. International Gas Union, “2016 World LNG Report,” April 12, 2016

32. International Energy Agency, “India Energy Outlook,” 2015.

33. In the deep decarbonization pathways for China and India, for example, natural gas plays a role in the energy systems. For more

information, see http://deepdecarbonization.org.

34. International Energy Agency, “Medium-Term Gas Market Report 2016,” 2016.

35. International Energy Agency, “World Energy Outlook 2016.”

36. International Energy Agency, “Medium-Term Gas Market Report 2016.”

37. International Energy Agency, “World Energy Model Documentation,” 2015.

38. The authors stress that the quantitative modeling, as presented in the discussion paper, is complementary to other evidence in this

paper, including the current state of gas markets, historical trends and developments, and the authors’ understanding of likely eco-

nomic developments within the Asia-Pacific region. Given the supply-and-demand fluctuations in global gas markets, which conse-

26

quently affect prices, scenario projections out to 2025 should be considered as indicative of possible trends and represent relative

effects on production and prices. They do not represent a forecast of what will be the actual state of gas markets in 2025. In other

words, the model results provide a lens on the possible effects of increased gas demand in China and India, relative to a baseline, ra-

ther a definitive prediction of outcomes. The purpose of the modeling and presentation of the findings is not to provide definitive

advice as to what will happen in 2025 but to give an indication of relative supply and price impacts of a scenario that assumes in-

creased gas demand in China and India relative to a baseline.

39. International Energy Agency, “World Energy Model Documentation.”

40. Anne-Sophie Corbeau and David Ledesma, eds., LNG Markets in Transition: The Great Reconfiguration (Oxford, U.K.: Oxford

Institute for Energy Studies, 2016.)

41. Jude Clemente, “China’s Rising Natural Gas Demand, Pipelines, and LNG,” Forbes, April 24, 2016.

42. Ernst and Young, “Gas Market in India: Overview and Future Outlook,” 2016; Michael Ratner, Gabriel M. Nelson, and Susan V.

Lawrence, “China’s Natural Gas: Uncertainty for Markets,” Congressional Research Service, May 2, 2016.

43. The results are scenario-based, rather than a forecast of what will happen by 2025. They provide a complementary set of evidence

of what could occur to gas supply and prices, relative to a baseline, given the assumption of much higher growth in gas demand in

China and India than generally assumed.

44. Xunpeng Shi and Hari Malamakkavu Padinjare Variam, “Gas and LNG Trading Hubs, Hub Indexation and Destination Flexibility

in East Asia,” Energy Policy 98, September 2016, pp. 587–96.